US20070261891A1

US20070261891A1 - Roller Cone Drill Bit With Enhanced Debris Diverter Grooves

Info

Publication number: US20070261891A1
Application number: US11/677,166
Authority: US
Inventors: Mark E. Williams; Michael B. Crawford; William C. Saxman; Mark P. Blackman; Gerald L. Pruitt
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2006-02-21
Filing date: 2007-02-21
Publication date: 2007-11-15
Also published as: CN101025076A; GB0703381D0; GB2435281A; ITMI20070336A1

Abstract

A roller cone drill bit having a bit body with at least one support arm extending from the bit body. Each support arm may have an interior surface and exterior surface with an associated spindle extending from the interior surface. A respective cone assembly may be rotatably disposed on each spindle. A gap formed between interior portions of each cone assembly and exterior portions of the associated spindle with a fluid seal disposed in the gap to block fluid flow therethrough. Each cone assembly includes a generally circular back surface disposed adjacent to the interior surface of the associated support arm. A flow diverter groove formed in the interior surface of each support arm spaced from the associated spindle. Each diverter groove having a variable geometry to enhance the flow of fluid containing downhole debris away from the associated real assembly, and each diverter groove having a variable geometry.

Description

RELATED APPLICATIONS

This application claims the benefit of provisional patent application entitled “Roller Cone Drill Bit With Enhanced Debris Diverter Grooves,” Application Ser. No. 60/775,648 filed Feb. 21, 2006.

TECHNICAL FIELD

The present disclosure is related to roller cone drill bits used to form wellbores in subterranean formations and more particularly to roller cone drill bits with debris diverter grooves.

BACKGROUND OF THE DISCLOSURE

A wide variety of roller cone and rotary cone drill bits have previously been used to form wellbores or boreholes in subterranean formations. Roller cone drill bits generally include at least one support arm and often three support arms. A respective cone assembly may be rotatably mounted on a spindle or journal extending inwardly from an interior surface each support arm. Small gaps are generally provided between adjacent portions of each support arm and associate cone assembly to allow rotation of the cone assembly relative to the respective support arm and spindle while drilling a wellbore.
Protection of bearings and related supporting structures which allow rotation of a cone assembly relative to an associated support arm and spindle may lengthen the life of an associated roller cone drill bit. Once downhole debris is allowed to infiltrate between bearing surfaces of a cone assembly and associated spindle, failure of the associated drill bit will generally follow shortly. Various mechanisms and techniques have been used to prevent debris from contacting such bearing surfaces.
A typical approach is to install a fluid seal in a gap formed between adjacent portions of each cone assembly and associated spindle. Such fluid seals maintain lubrication in bearings and associated supporting structures and prevent intrusion of shale, formation cuttings and other types of downhole debris. Once the fluid seal fails, downhole debris may quickly contaminate bearing surfaces via the gap. Thus, it is important that fluid seals also be protected against damage caused by downhole debris.
Various approaches have previously been used to protect fluid seals in roller cone drill bits from downhole debris. One approach is to install hardfacing and/or wear buttons on opposite sides of gaps formed between each cone assembly and associated support arm proximate exterior portions of the drill bit. Hardfacing and wear buttons generally slow erosion of metal adjacent to such gaps to prolong downhole drilling time before an associated fluid seal may be exposed to downhole debris. Another approach is to form tortuous fluid flow paths proximate each gap leading to an associated fluid seal. Tortuous fluid flow paths allow rotation of a cone assembly relative to an associated spindle but are often difficult for downhole debris to follow.
Various types of debris diverter plugs, sometimes referred to as “shale burn compacts” or “shale burn plugs”, have been installed on interior surfaces of support arms proximate portions of an associated cone assembly. Such diverter plugs may block or direct fluids containing downhole debris away from an associated fluid seal. Also, debris diverter grooves, sometimes referred to as “shale diverter grooves”, have been formed in interior surfaces of support arms adjacent to an associated cutter cone assembly. Debris diverter grooves may direct fluids containing downhole debris away from an associated fluid seal.

SUMMARY OF THE DISCLOSURE

In accordance with teachings of the present disclosure, various disadvantages and problems associated with prior roller cone drill bits may be substantially reduced or eliminated. One aspect of the present disclosure may include extending the downhole drilling life of fluid seals which prevent small particles of shale, formation cuttings and other types of downhole debris from damaging bearings and associated bearing structures. For some applications, a roller cone drill bit may have at least one support arm with a debris diverter groove disposed in an interior surface of the support arm. The debris diverter groove may have variations in dimensions and/or configuration to enhance the flow of fluids containing shale, formation cuttings and other types of debris away from an associated fluid seal.
Technical benefits of the present disclosure may include providing roller cone drill bits with the diverter grooves having variations in dimensions and/or configurations to reduce or eliminate the tendency of shale, formation cuttings and other types of debris to adhere to or stick within such diverter grooves. The overall effectiveness of such diverter grooves in directing fluid containing debris away from associated fluid seals may be enhanced. For some applications a diverter groove may be formed with increasing cross-sectional area or fluid flow area in the direction of rotation of an associated cone assembly relative to adjacent portions of a support arm to substantially reduce or prevent debris from restricting fluid flow through the diverter groove. For such applications the diverter groove may be described as having an increasing cross-sectional area or increasing fluid flow area extending from a trailing edge to a leading edge of the associated support arm to substantially reduce or prevent debris from restricting fluid flow through the diverter groove.
Various teachings of the present disclosure may be used to increase the cross-sectional area or fluid flow area of a diverter groove including, but not limited to, increasing the width and/or depth of the diverter groove. Also, the cross-sectional area or fluid flow area may be increased by changing various geometrical features such as the radial distance of one or more segments of a diverter groove relative to an associated spindle. A diverter groove incorporating teachings of the present disclosure may include a nonsymmetrical configuration or shape relative to an associated spindle. For some applications one or more diverter plugs may be disposed adjacent to such diverter grooves.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete and thorough understanding of the present embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, in which like reference numbers indicate like features, and wherein:

FIG. 1A is a schematic drawing in section and in elevation with portions broken away showing examples of wellbores which may be formed by a roller cone drill bit incorporating teachings of the present disclosure;

FIG. 1B is an enlarged schematic drawing in section and in elevation with portions broken away showing the drill string and attached roller cone drill bit of FIG. 1A adjacent to the bottom of a wellbore;

FIG. 2 is a schematic drawing in elevation showing a roller cone drill bit incorporating teachings of the present disclosure;

FIG. 3 is a schematic drawing partially in section and partially in elevation with portions broken away showing a support arm and cone assembly incorporating teachings of the present disclosure;

FIG. 4A is a schematic drawing showing an isometric view with portions broken away of a support arm incorporating teachings of the present disclosure;

FIGS. 4B, 4C and 4D are schematic drawings in section with portions broken away showing variations in fluid flow area of a debris diverter groove formed in the support arm of FIG. 4A;

FIG. 5A is a schematic drawing showing an isometric view with portions broken away of a support arm incorporating teachings of the present disclosure;

FIGS. 5B, 5C and 5D are schematic drawings in section with portions broken away showing variations in fluid flow area of a debris diverter groove formed in the support arm of FIG. 5A;

FIG. 6A a is schematic drawing showing an isometric view with portions broken away of a support arm incorporating teachings of the present disclosure;

FIGS. 6B, 6C and 6D are schematic drawings in section with portions broken away showing variations in fluid flow area of a diverter groove formed in the support arm of FIG. 6A;

FIG. 7A is a schematic drawing showing an isometric view with portions broken away of a support arm incorporating teachings of the present disclosure; and

FIGS. 7B, 7C and 7D are schematic drawings in section with portions broken away showing variations in fluid flow area of a diverter groove formed in the support arm of FIG. 7A.

DETAILED DESCRIPTION OF THE DISCLOSURE

Preferred embodiments of the disclosure and its advantages are best understood by reference to FIGS. 1A-7D wherein like number refer to same and like parts.
The term “debris” may be used in this application to refer to any type of material such as, but not limited to, formation cuttings, shale, abrasive particles, or other downhole debris associated with forming a wellbore in a subterranean formation using a roller cone drill bit.
The term “diverter plug” may be used in this application to include any shale burn plug, shale diverter plug, debris diverter plug and debris diverter insert which may be installed in a support arm of a roller cone drill bit. Such diverter plugs may be used to block or redirect the flow of fluid containing downhole debris away from fluid seals in associated cone assemblies.
The term “cone assembly” may be used in this application to include various types and shapes of roller cone assemblies and cutter cone assemblies rotatably mounted to a support arm. Cone assemblies may also be referred to as “roller cones” or “cutter cones.” Cone assemblies may have a generally conical exterior shape or may have a more rounded exterior shape. Cone assemblies associated with roller cone drill bits generally point inwards towards each other. For some applications, such as roller cone drill bits having only one cone assembly, the cone assembly may have an exterior shape approaching a generally spherical configuration.
The terms “cutting element” and “cutting elements” may be used in this application to include various types of compacts, inserts, milled teeth and welded compacts satisfactory for use with roller cone drill bits. The terms “cutting structure” and “cutting structures” may be used in this application to include various combinations and arrangements of cutting elements formed on or attached to one or more cone assemblies of a roller cone drill bit.
The term “bearing structure” may be used in this application to include any suitable bearing, bearing system and/or supporting structure satisfactory for rotatably mounting a cone assembly on a support arm. For example, a “bearing structure” may include inner and outer races and bushing elements to form a journal bearing, a roller bearing (including, but not limited to a roller-ball-roller-roller bearing, a roller-ball-roller bearing, and a roller-ball-friction bearing) or a wide variety of solid bearings. Additionally, a bearing structure may include interface elements such a bushings, rollers, balls, and areas of hardened materials used for rotatably mounting a cone assembly with a support arm.
The term “spindle” may be used in this application to include any suitable journal, shaft, bearing pin or structure satisfactory for use in rotatably mounting a cone assembly on a support arm. A bearing structure is typically disposed between adjacent portions of a cone assembly and a spindle to allow rotation of the cone assembly relative to the spindle and associated support arm.
The term “fluid seal” may be used in this application to include any type of seal, seal ring, backup ring, elastomeric seal, seal assembly or any other component satisfactory for forming a fluid barrier between adjacent portions of a cone assembly and an associated spindle. Examples of fluid seals associated with roller cone drill bits include, but are not limited to, O-rings, packing rings, and metal-to-metal seals. Fluid seals may be disposed in seal grooves or seal glands.
The term “roller cone drill bit” may be used in this application to describe any type of drill bit having at least one support arm with a cone assembly rotatably mounted thereon. Roller cone drill bits may sometimes be described as “rotary cone drill bits,” “cutter cone drill bits” or “rotary rock bits”. Roller cone drill bits often include a bit body with three support arms extending therefrom and a respective cone assembly rotatably mounted on each support arm. Such drill bits may also be described as “tri-cone drill bits”. However, teachings of the present disclosure may be satisfactorily used with drill bits having one support arm, two support arms or any other number of support arms and associated cone assemblies.
FIG. 1A is a schematic drawing in elevation and in section with portions broken away showing examples of wellbores or boreholes which may be formed by roller cone drill bits incorporating teachings of the present disclosure. Various aspects of the present disclosure may be described with respect to drilling rig 20 located at well surface 22. Various types of drilling equipment such as a rotary table, mud pumps and mud tanks (not expressly shown) may be located at well surface 22. Drilling rig 20 may have various characteristics and features associated with a “land drilling rig.” However, roller cone drill bits incorporating teachings of the present disclosure may be satisfactorily used with drilling equipment located on offshore platforms, drill ships, semi-submersibles and drilling barges (not expressly shown).
Roller cone drill bit 40 as shown in FIGS. 1A, 1B and 2 may be attached with the end of drill string 24 extending from well surface 22. Roller cone drill bits such as drill bit 40 typically form wellbores by crushing or penetrating a formation and scraping or shearing formation materials from the bottom of the wellbore using cutting elements which often produce a high concentration of fine, abrasive particles.
Drill string 24 may apply weight to and rotate roller cone drill bit 40 to form wellbore 30. Axis of rotation 46 of roller cone drill bit 40 may sometimes be referred to as “bit rotational axis”. See FIG. 2. The weight of associated drill string 25 (sometimes referred to as “weight on bit”) will generally be applied to roller cone drill bit 40 along bit rotational axis 46.
For some applications various types of downhole motors (not expressly shown) may also be used to rotate a roller cone drill bit incorporating teachings of the present disclosure. The present disclosure is not limited to roller cone drill bits associated with conventional drill strings.
Drill string 24 may be formed from sections or joints of generally hollow, tubular drill pipe (not expressly shown). Drill string 24 may also include bottom hole assembly 26 formed from a wide variety of components. For example components 26 a, 26 b and 26 c may be selected from the group consisting of, but not limited to, drill collars, rotary steering tools, directional drilling tools and/or a downhole drilling motor. The number of components such as drill collars and different types of components in a bottom hole assembly will depend upon anticipated downhole drilling conditions and the type of wellbore which will be formed by drill string 24 and roller cone drill bit 40.
Roller cone drill bit 40 may be attached with bottom hole assembly 26 at the end of drill string 24 opposite well surface 22. Bottom hole assembly 26 will generally have an outside diameter compatible with other portions of drill string 24. Drill string 24 and roller cone drill bit 40 may be used to form various types of wellbores and/or boreholes. For example, horizontal wellbore 30 a, shown in FIG. 1A in dotted lines, may be formed using drill string 24 and roller cone drill bit 40. Horizontal wellbores are often formed in “chalk” formations and other types of shale formations. Interaction between roller cone drill bit 40 and chalk or shale type formations may produce a large amount of fine, highly abrasive particles and other types of downhole debris.
Wellbore 30 may be defined in part by casing string 32 extending from well surface 22 to a selected downhole location. As shown in FIGS. 1A and 1B remaining portions of wellbore 30 may be described as “open hole” (no casing). Drilling fluid may be pumped from well surface 22 through drill string 24 to attached roller cone drill bit 40. The drilling fluid may be circulated back to well surface 22 through annulus 34 defined in part by outside diameter 25 of drill string 24 and inside diameter 31 of wellbore 30. Inside diameter 31 may also be referred to as the “side wall” of wellbore 30. For some applications annulus 34 may also be defined by outside diameter 25 of drill string 24 and inside diameter 33 of casing string 32.
The type of drilling fluid used to form wellbore 30 may be selected based on design characteristics associated with roller cone drill bit 40, anticipated characteristics of each downhole formation being drilled and any hydrocarbons or other fluids produced by one or more downhole formations adjacent to wellbore 30. Drilling fluids may be used to remove formation cuttings and other downhole debris (not expressly shown) from wellbore 30 to well surface 22. Formation cuttings may be formed by roller cone drill bit 40 engaging end 36 of wellbore 30. End 36 may sometimes be described as “bottom hole” 36. Formation cuttings may also be formed by roller cone drill bit 40 engaging end 36 a of horizontal wellbore 30 a. Drilling fluids may assist in forming wellbores 30 and/or 30 a by breaking away, abrading and/or eroding adjacent portions of downhole formation 38. As a result drilling fluid surrounding roller cone drill bit 40 at end 36 of wellbore 30 may have a high concentration of fine, abrasive particles and other types of debris.
Drilling fluid is typically used for well control by maintaining desired fluid pressure equilibrium within wellbore 30. The weight or density of a drilling fluid is generally selected to prevent undesired fluid flow from an adjacent downhole formation into an associated wellbore and to prevent undesired flow of the drilling fluid from the wellbore into the adjacent downhole formation. Various additives may be used to adjust the weight or density of drilling fluids. Such additives and/or the resulting drilling fluid may sometimes be described as “drilling mud”. Additives used to form drilling mud may include small, abrasive particles capable of damaging fluid seals and bearing structures of an associated roller cone drill bit. Sometimes additives (mud) in drilling fluids may accumulate on or stick to one or more surfaces of a roller cone drill bit.
Drilling fluids may also provide chemical stabilization for formation materials adjacent to a wellbore and may prevent or minimize corrosion of a drill string, bottom hole assembly and/or attached rotary drill bit. Drilling fluids may also be used to clean, cool and lubricate cutting elements, cutting structures and other components associated with roller cone drill bits 40.
Roller cone drill bit 40 may include bit body 42 having tapered, externally threaded, upper portion 44 satisfactory for use in attaching roller cone drill bit 40 with drill string 24. A wide variety of threaded connections may be satisfactorily used to attach roller cone drill bit 40 with drill string 24 and to allow rotation of roller cone drill bit 40 in response to rotation of drill string 24 at well surface 22.
An enlarged cavity (not expressly shown) may be formed adjacent to upper portion 42 to receive drilling fluid from drill string 24. Such drilling fluids may be directed to flow from drill string 24 to respective nozzles 150 provided in roller cone drill bit 40. A plurality of drilling fluid passageways (not expressly shown) may be formed in bit body 42. Each drilling fluid passageway may extend from the associated enlarged cavity to respective receptacle 48 formed in bit body 42. The location of receptacles 48 may be selected based on desired locations for nozzles 150 relative to associated cone assemblies 90.
Formation cuttings formed by roller cone drill bit 40 and any other downhole debris at end 36 of wellbore 30 will mix with drilling fluids exiting from nozzles 150. The mixture of drilling fluid, formation cuttings and other downhole debris will generally flow radially outward from beneath roller cone drill bit 40 and then flow upward to well surface 22 through annulus 34.
Roller cone drill bit 40, bit body 42, support arms 50 and associated cone assemblies 90 may be substantially covered by or immersed in a mixture of drilling fluid, formation cuttings and other downhole debris while drill string 24 rotates roller cone drill bit 40. This mixture of drilling fluid, formation cuttings and/or formation fluids may include highly abrasive materials.
Bit body 42 may be formed from three segments which include respective support arms 50 extending therefrom. The segments may be welded with each other using conventional techniques to form bit body 42. Only two support arms 50 are shown in FIGS. 1A, 1B and 2.
Each support arm 50 may be generally described as having an elongated configuration defined in part by interior surface 52 and exterior surface 54. Each support arm 50 may include respective spindle 70 extending inwardly from associated interior surface 52. Each support arm 50 may also include respective leading edge 56 and trailing edge 58 which terminate at respective end 60 spaced from bit body 42.
Portions of exterior surface 54 opposite from associated spindle 70 may sometimes be referred to as the “shirt tail” or “shirt tail surface” of each support arm 50. The shirt tail may sometimes be defined as the exterior portion of a support arm below an associated nozzle. Exterior portions of each support arm 50 adjacent to respective end 60 may sometimes be described as the “shirt tail tip”. Interior surface 52 and exterior surface 54 of each support arm 50 are generally contiguous with each other along respective leading edge 56, trailing edge 58 and respective end 60.
Spindles 70 may be angled downwardly and inwardly with respect to associated interior surfaces 52. As a result, exterior portions of each cone assembly 90 may engage the bottom or end 36 of wellbore 30 as roller cone drill bit 40 is rotated by drill string 24. For some applications spindles 70 may be tilted at an angle of zero to three or four degrees in the direction rotation of roller cone drill bit 40.
Cone assemblies 90 may be rotatably mounted on respective spindles 70 extending from each support arm 50. Each cone assembly 90 may include respective axis of rotation 100 extending at an angle corresponding generally with the angular relationship between associated spindle 70 and support arm 50. Axis of rotation 100 for each cone assembly 90 generally corresponds with the longitudinal center line or longitudinal axis of associated spindle 70. The axis of rotation of each cone assembly 90 may be offset relative to longitudinal axis or rotational axis 46 of roller cone drill bit 40. See FIG. 2.
Various types of retaining systems and locking systems may be satisfactorily used to securely engage each cone assembly 90 with associated spindle 70. For some applications a ball passageway (not expressly shown) may be formed extending from exterior surface 54 through associated spindle 70. Each cone assembly 90 may be retained on associated spindle 70 by inserting a plurality of ball bearings 78 through the associated ball passageway. Ball bearings 78 may be disposed within respective ball races 76 and 106 formed on adjacent portions of spindle 70 and cavity 102 of associated cone assembly 90. A ball retainer plug (not expressly shown) may also be inserted into the ball passageway. Once inserted, ball bearings 78 and ball races 76 and 106 cooperate with each other to prevent disengagement of cone assembly 90 from associated spindle 70.
For some applications a plurality of compacts 92 may be disposed in gage surface 93 adjacent to backface 94 of each cone assembly 90. Compacts 92 may be used to prevent wear to gage surface 93 adjacent to backface 94 of associated cone assembly 90. Backface 94 may sometimes be referred to as a “base” for associated cone assembly 90.
Each cone assembly 90 may also include a plurality of cutting elements 96 arranged in respective rows formed on the exterior of each cone assembly 90 between associated cone backface 94 and cone tip 98. A gauge row of cutting element 96 may be disposed adjacent to backface 94 of each cone assembly 90. The gauge row may also sometimes be referred to as the “first row” of inserts.
Compacts 92 and cutting elements 96 may be formed from a wide variety of materials such as tungsten carbide. The term “tungsten carbide” includes monotungsten carbide (WC), ditungsten carbide (W₂C), macrocrystalline tungsten carbide and cemented or sintered tungsten carbide. Examples of hard materials which may be satisfactorily used to form compacts 92 and cutting elements 96 may include various metal alloys and cermets such as metal borides, metal carbides, metal oxides and metal nitrides. For some applications compacts 92 and/or inserts 96 may be formed from polycrystalline diamond type materials or other suitable hard, abrasive materials.
Cutting elements 96 may scrape and gouge the sides and bottom of wellbore 30 in response to weight and rotation applied to roller cone drill bit 40 by drill string 24. The interior diameter or side wall 31 of wellbore 30 correspond approximately with the combined outside diameter of cone assemblies 90 attached with roller cone drill bit 40.
The position of cutting elements 96 on each cone assembly 90 may be varied to provide desired downhole drilling action. Other types of cone assemblies may be satisfactorily used with the present disclosure including, but not limited to, cone assemblies having milled teeth (not expressly shown) instead of cutting elements 96.
Various types of bearing structures may be used to rotatably mount each cone assembly 90 on associated spindle 70. For example, each spindle 70 may include generally cylindrical exterior surfaces such as bearing surface 74. Each cone assembly 90 may include respective cavity 102 extending inwardly from associated backface 94. Each cavity 102 may include generally cylindrical interior surfaces such as bearing surface 104. The cylindrical portions of each cavity 102 may have a respective inside diameter which is generally larger than the outside diameter of an adjacent cylindrical portion of spindle 70.
Variations between the inside diameter of each cavity 102 and outside diameter of associated spindle 70 are selected to accommodate the associated bearing structure and allow rotation of each cone assembly 90 relative to associated spindle 74 and adjacent portions of support arm 50. The actual difference between the outside diameter of bearing surface 74 and the inside diameter of bearing surface 104 may be relatively small to provide desired bearing support or rotational support for each cone assembly 90 relative to associated spindle 70.
Bearing surfaces 74 and 104 support radial loads resulting from rotation of each cone assembly 90 relative to associated spindle 70. Thrust flange 82 may be formed on spindle 70 between ball race 76 and pilot bearing surface 84. Thrust flange 82 typically supports axial loads resulting from weight on roller cone bit 40 and rotation of each cone assembly 90 relative to associated spindle 70. For some applications thrust button or thrust bearing 80 may also be provided in cavity 102 of each cone assembly 90 at the end of spindle 70 opposite from associated support arm 50.
A generally cylindrical gap may be formed between exterior portions of spindle 70 and interior portions of cavity 102 of associate cone assembly 90. The generally cylindrical gap may be defined in part by adjacent bearing surface 74 and 104. The generally cylindrical gap may also include segments of spindle 70 and cavity 102 adjacent to fluid seal 108.
One or more machined surfaces are often formed on the interior surface of a support arm adjacent to and extending from an associated spindle. For embodiments such as shown in FIGS. 3, 4A, 5A, 6A and 7A each support arm 50 may be generally described as having respective machined surfaces 64 extending radially from associated spindle 70. Machined surfaces 64 may terminate proximate leading edge 56, trailing edge 58 and shirt tail tip 60 of associated support arm 50.
As shown in FIG. 3, gap 62 may be formed between cone backface 94 and adjacent portions of machined surfaces 64 formed on interior surface 52 of associated support arm 50. Gap 62 may sometimes be generally described as a “clearance gap”. Gap 62 allows rotation of each cone assembly 90 relative to machined surfaces 64 of associated support arm 50. Gap 62 also extends from and communicates with the generally cylindrical gap formed between exterior portions of spindle 70 and interior portions of cavity 102 of associated cone assembly 90.
Each support arm 50 may include a lubricant system (not expressly shown) having a lubricant reservoir, lubricant pressure compensator and one or more lubricant passageways to provide lubrication to various components of associated spindle 70 and cone assembly 90. One or more passageways, not expressly shown, may be provided within spindle 70 to supply lubrication to bearing surfaces 74 and 104, ball races 76 and 106 and/or thrust bearing flange 82.
One or more fluid seals may be provided to block fluid communication through the generally cylindrical gap formed between exterior portions of spindle 70 and interior portions of cavity 102 in associated cone assembly 90. As shown in FIG. 3, fluid seal 108 may be engaged with exterior portions of spindle 70 and interior portions of cavity 102 located between bearing surfaces 74 and 104 and machined surface 64 formed on interior surface 52 of associated support arm 90. For some applications fluid seal 108 may include a seal ring or packing disposed in a seal gland (not expressly shown).
Fluid seal 108 may be used to block the flow of drilling fluid and any other fluid containing debris from communicating with bearing surfaces 74, 104 and ball races 76 and 106. Fluid seal 108 may also form a fluid barrier to prevent lubricant contained between cavity 102 and spindle 70 from exiting therefrom. Fluid seals 108 protect associated bearing structures from loss of lubricant and from contamination with debris and thus prolong the downhole drilling life of roller cone drill bit 40.
Drilling fluid containing formation cuttings and other downhole debris may enter into gap 62 formed between interior surface 52 and backface 94 of each cone assembly 90. Rotation of each cone assembly 64 often results in forcing (pumping) drilling fluid and associated debris into 62 and the generally cylindrical gap formed between each spindle 70 and associated cone assembly 90. The movement of such drilling fluid may often result in packing debris against associated fluid seal 108 causing the debris to form a substantially solid layer. The layer of debris may force fluid seal 108 to move axially in an associated seal gland until fluid seal 108 reaches the end of the seal gland where continued forces (packing of debris) may increase the pressure on fluid seal 108 beyond the design range of the associated seal material.
For some applications diverter groove 120 may be formed in interior surface 52 extending from trailing edge 58 to trailing edge 56 of each support arm 50. Diverter groove 120 may provide a fluid flow path having a substantially larger fluid flow area as compared with relatively small gap 62 formed between adjacent portions of backface 94 and machined surfaces 64. As a result diverter groove 120 will generally divert or direct drilling fluid and any other fluid containing debris away from associated fluid seal 108. Diverter groove 120 may sometimes be referred to as a shale diverter groove or a debris diverter groove.
One aspect of the present disclosure may include forming diverter grooves having variations in fluid flow area to reduce or eliminate the tendency of debris including additives in drilling fluid to stick with or coat surfaces of a diverter groove. Sometimes debris may accumulate in a conventional diverter groove having a generally uniform or constant fluid flow area and substantially restrict or block fluid flow therethrough. A substantial increase in debris packed against an associated fluid seal may result if debris accumulates in and blocks or restricts fluid flow through a diverter groove. Examples of diverter grooves incorporating teachings of the present disclosure to substantially reduce or minimize packing of debris in such diverter grooves are shown in FIGS. 4A-7D.
Varying the fluid flow area in accordance with teachings of the present disclosure may enhance the ability of a diverter groove to divert or direct drilling fluids and other fluids containing debris away from an associated fluid seal. One or more diverter plugs (not expressly shown) may also be installed at an optimum location in machined surfaces 64 or other portions of interior surface 52 to increase flow of fluid containing downhole debris into associated diverter groove 120.
The support arms shown in FIGS. 4A, 5A, 6A and 7A may have substantially similar configurations and dimensions except for associated diverter grooves 120. For purposes of describing various features of the present invention, respective support arms shown in FIGS. 4A, 5A, 6A and 7A have been designated as support arms 50 a, 50 b, 50 c and 50 d. In a similar manner associated diverter grooves 120 shown in FIGS. 4A, 5A, 6A and 7A have been designated as diverter grooves 120 a, 120 b, 120 c and 120 d.
Each diverter groove 120 a, 120 b, 120 c and 120 d may be generally described as having respective first edge 121 and second edge 122. Each first edge 121 may be formed in respective machined surface 64 extending in an arc from leading edge 56 to trailing edge 58 of associated support arm 50 a, 50 b, 50 c and 50 d. For some applications (but not all) first edge 121 may be defined in part by a generally uniform radius extending from the longitudinal center line of associated spindle 70.
Each second edge 122 may be formed in respective machine surface 64 and/or portions of associated interior surface 52 which have not been machined. Each second edge 122 may extend between leading edge 56 and trailing edge 58 in a generally arcuate configuration relative to associated spindle 70. The location and configuration of each second edge 122 may be varied with respect to associated first edge 121 and/or spindle 70 in accordance with teachings of the present disclosure.
When cone assembly 90 is rotatably mounted on associated spindle 70, cone backface 94 may cover all or portions of associated diverter groove 120 a, 120 b, 120 c or 120 d. Arrow 91 as shown in FIGS. 4A, 5A, 6A and 7A indicates the general direction of rotation of cone assembly 90 relative to spindle 70, machined surfaces 64 and associated diverter groove 120 a, 120 b, 120 c, or 120 d. First edge 121 of each diverter groove 120 a, 120 b, 120 c and 120 d will typically be disposed beneath and covered by associated backface 94. For some applications portions of second edge 122 proximate leading edge 56 of associated support arm 50 may not be completely covered by backface 54 of associated cone assembly 90.
One of the benefits of the present disclosure includes varying the location of first edge 121 and/or 122 relative to spindle 70 and/or backface 94 of associated cone assembly 90. Diverter groove 120 a, 120 b, 120 c and 120 d may be defined in part by respective width 124 extending between associated first edge 121 and second edge 122 and respective depth 126. The width and depth of each diverter groove 120 a-120 d may be varied in accordance with the teachings of the present disclosure.
For some applications diverter grooves 120 a, 120 b and 120 c may be described as having a generally rectangular cross-section. Diverter grooves 120 a, 120 b and 120 c may also be described as generally U-shaped or C-shaped channels. Diverter groove 120 d may be described as having a generally curved cross-section defined in part by a segment of a circle. However, diverter grooves may be formed with a wide variety of cross-sections other than the cross-sections shown in FIGS. 4A-7D.
For embodiments such as shown in FIGS. 4A-4D width 124 of diverter groove 120 a may increase between trailing edge 58 and leading edge 56 of support arm 50 a. Height 126 of diverter groove 120 a may be relatively constant between trailing edge 58 to leading edge 56 of support arm 50 a. As a result of increasing width 124, the cross-sectional area or available fluid flow area in diverter groove 120 a will generally increase from leading edge 56 to trailing edge 58 of support arm 50 a.
FIG. 4B may be representative of the cross-section of diverter groove 120 a proximate trailing edge 58 of support arm 50 a. The cross-section of diverter groove 120 a shown in FIG. 4C may be representative of the cross-section of diverter groove 120 a approximately half way between trailing edge 58 and leading edge 56 of support arm 50 a. The cross-section shown in FIG. 4D may be representative of the cross-section of diverter groove 120 a proximate leading edge 56 of support arm 50 a.
For embodiments such as shown in FIGS. 5A-5D diverter groove 120 b may be described as having a generally uniform width 124 extending from trailing edge 58 to leading edge 56 of support arm 50 b. However, depth 126 of diverter groove 120 b may increase from trailing edge 58 to leading edge 56 of support arm 50 b. Depth 126 may also increase relative to backface 94 of associated cone assembly 90. As a result of increasing depth 126, the cross-sectional area or available fluid flow area in diverter groove 120 b will generally increase from trailing edge 58 to leading edge 56 of support arm 50 b.
FIG. 5B may be representative of the cross-section of diverter groove 120 b proximate trailing edge 58 of support arm 50 b. The cross-section of diverter groove 120 b shown in FIG. 5C may be representative of the cross-section of diverter groove 120 b approximately halfway between trailing edge 58 and leading edge 56 of support arm 50 b. The cross-section shown in FIG. 5D may be representative of the cross-section of diverter groove 120 b proximate leading edge 56 of support arm 50 b.
For embodiments such as shown in FIGS. 6A-6D, diverter groove 120 c may be described as having both increasing width 124 and increasing depth 126 extending from trailing edge 58 to leading edge 56 of support arm 50 c. Depth 126 may also increase relative to backface 94 of associated cone assembly 90. As a result of increasing width 124 and increasing depth 126, the cross-sectional area or available fluid flow area in diverter groove 120 c will generally increase from trailing edge 58 to leading edge 56 of support arm 50 c.
FIG. 6B may be representative of the cross-section of diverter groove 120 c proximate trailing edge 58 of support arm 50 c. The cross-section of diverter groove 120 c shown in FIG. 6C may be representative of the cross-sectional area of diverter groove 120 c approximately halfway between trailing edge 58 and leading edge 56 of support arm 50 c. The cross-section shown in FIG. 6D may be representative of the cross-section of diverter groove 120 c proximate leading edge 56 of support arm 50 c.
For embodiments such as shown in FIGS. 7A-7D, diverter groove 120 d may be generally described as having a cross-section defined in part by a segment of a circle. Diverter groove 120 d may also be generally described as having increasing depth and increasing width extending from trailing edge 58 to leading edge 56 of support arm 50 d. Depth 126 may also increase relative to backface 94 of associated cone assembly 90. As a result of increasing width 124 and increasing depth 126, the cross-sectional area or available fluid flow area in diverter groove 120 d will generally increase from trailing edge 58 to leading edge 56 of support arm 50 d. For some applications each cross-section associated with diverter groove 120 d may be a segment of a circle having substantially the same radius 59. For other applications a diverter groove (not expressly shown) may be formed with cross-sections corresponding to segments of respective circles in which each circle has an increasing radius (not expressly shown).
FIG. 7B may be representative of the cross-section of diverter groove 120 d proximate trailing edge 58 of support arm 50 d. The cross-section of diverter groove 120 d shown in FIG. 7C may be representative of the cross-section of diverter groove 120 d approximately halfway between trailing edge 58 and leading edge 56 of support arm 50 d. The cross-section shown in FIG. 7D may be representative of the cross-section of diverter groove 120 d proximate leading edge 56 of associated support arm 50 d.
Increasing the fluid flow area in the direction of rotation of cone assembly 90 relative to machined surfaces 64 between trailing edge 58 and leading edge 56 of respective diverter grooves 120 a, 120 b, 120 c and 120 d may substantially eliminate or reduce the possibility of debris including additives in associated drilling fluid coating, sticking to or adhering with respective surfaces of diverter grooves 120 a, 120 b, 120 c and 120 d to block or restrict fluid flow therethrough. As a result, associated fluid seals 108 and bearing structures protected by fluid seals 108 may have an increased downhole drilling life. Increasing the downhole drilling life of fluid seals and bearing structures will often increase the downhole drilling life of an associated roller cone drill bit.
Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims.

Claims

1. A roller cone drill-bit comprising:

a bit body having at least one support arm extending therefrom;

each support arm having a leading edge and a trailing edge;

each support arm having a first, interior surface with a spindle extending therefrom;

an associated cone assembly having a cavity formed therein;

the cavity defined in part by interior surfaces sized to receive corresponding exterior surfaces formed on the spindle;

a respective bearing structure disposed between exterior surfaces of each spindle and interior surfaces of each cone assembly;

a fluid seal disposed in a first, generally cylindrical gap formed between interior portions of each cone assembly and exterior portions of the associated spindle;

a diverter groove formed on the interior surface of each support arm spaced from the associated spindle;

each diverter groove extending from the leading edge to the trailing edge of the associated support arm;

each diverter groove operable to direct fluid containing debris away from the associated fluid seal; and

each diverter groove having an increasing cross-sectional area extending from the leading edge to the trailing edge to minimize possible packing of debris in the respective diverter groove.

2. The roller cone drill bit of claim 1 wherein each diverter groove further comprises an inlet disposed proximate the leading edge of the associated support arm and an outlet disposed proximate the trailing edge of the associated support arm.

3. The roller cone drill bit of claim 2 wherein each diverter groove further comprises:

a generally u-shaped cross-section defined in part by a width and a height; and

the height of the cross-section of the diverter groove at the leading edge less than the height of the cross-section of the diverter groove at the trailing edge.

4. The roller cone drill bit of claim 2 further comprising:

a cross-section defined in part by a width and a height; and

the height of the cross-section of the diverter groove relative to the backface of the associated cone assembly at the leading edge less than the height of the cross-section of the diverter groove at the trailing edge.

5. The roller cone drill bit of claim 2 further comprising:

each diverter groove having a generally u-shaped cross-section defined in part by a width and a height;

the width of the cross-section of the diverter groove at the leading edge less than the width of the cross-section of the diverter groove at the trailing edge.

6. The roller cone drill bit of claim 1 further comprising:

the diverter groove further comprising an inlet disposed proximate the leading edge of the associated support arm and an outlet disposed proximate the trailing edge of the associated support arm;

the diverter groove having a generally u-shaped cross-section defined in part by a width and a height;

the height of the cross-section of the diverter groove at the leading edge smaller than the height of the cross-section of the diverter groove at the trailing edge; and

the width of the cross-section of the diverter groove at the leading edge smaller than the width of the cross-section at the trailing edge.

7. The roller cone drill bit of claim 1 further comprising:

the diverter groove having a generally u-shaped cross-section defined in part by a radius; and

the radius of the cross-section of the diverter groove at the leading edge less than the radius of the cross-section of the diverter groove at the trailing edge.

8. The roller cone drill bit of claim 1 wherein each diverter groove further comprises a cross-section selected from the group consisting of a generally u-shaped cross-section, a segment of a circle and a generally rectangular cross-section.

9. The roller cone drill bit of claim 1 further comprising each support arm having a second, exterior surface opposite from the first interior surface and the spindle.

10. The roller cone drill bit of claim 1 further comprising each diverter groove having a first edge and a second edge formed adjacent to the interior surface of the associated support arm.

11. The roller cone drill bit of claim 1 further comprising at least one diverter plug disposed on the interior surface of the associated support arm to assist in directing fluids containing debris into the respective diverter groove.

12. A roller cone drill bit comprising:

a bit body having three support arms extending therefrom;

each support arm having a leading edge and a trailing edge;

an associated cone assembly having a cavity formed therein;

a debris diverter groove formed on the interior surface of each support arm spaced from the associated spindle;

each debris diverter groove extending from the leading edge to the trailing edge of the associated support arm;

each debris diverter groove operable to direct fluid containing debris away from the associated fluid seal; and

each debris diverter groove having variations in dimensions and/or configuration to provide enhanced protection for associated fluid seals and bearing systems by diverting shale, formation cutting and other types of downhole debris away from such fluid seals and bearing systems.

13. The roller cone drill bit of claim 12 wherein each debris diverter groove further comprises an inlet disposed proximate the leading edge of the associated support arm and an outlet disposed proximate the trailing edge of the associated support arm.

14. The roller cone drill bit of claim 13 wherein each debris diverter groove further comprises:

a generally u-shaped cross-section defined in part by a width and a height; and

the height of the cross-section of the debris diverter groove at the leading edge less than the height of the cross-section of the debris diverter groove at the trailing edge.

15. The roller cone drill bit of claim 1 further comprising:

a cross-section defined in part by a width and a height; and

16. The roller cone drill bit of claim 13 further comprising:

each debris diverter groove having a generally u-shaped cross-section defined in part by a width and a height;

the width of the cross-section of the debris diverter groove at the leading edge less than the width of the cross-section of the debris diverter groove at the trailing edge.

17. The roller cone drill bit of claim 12 further comprising:

the debris diverter groove further comprising an inlet disposed proximate the leading edge of the associated support arm and an outlet disposed proximate the trailing edge of the associated support arm;

the debris diverter groove having a generally u-shaped cross-section defined in part by a width and a height;

18. The roller cone drill bit of claim 12 further comprising:

19. The roller cone drill bit of claim 12 wherein each debris diverter groove further comprises a cross-section selected from the group consisting of a generally u-shaped cross-section, a generally c-shaped cross-section, and a generally rectangular cross-section.

20. The roller cone drill bit of claim 12 further comprising each support arm having a second, exterior surface opposite from the first interior surface and the spindle.

21. The roller cone drill bit of claim 12 further comprising each debris diverter groove having a first edge and a second edge formed adjacent to the interior surface of the associated support arm.

22. The roller cone drill bit of claim 12 further comprising at least one diverter plug disposed on the interior surface of the associated support arm to assist in directing fluids containing debris into the respective debris diverter groove.

23. A method of forming a roller cone drill bit having enhanced protection for associated fluid seals comprising:

forming a bit body having a first end operable to be releasably engaged with a drill string and at least one support arm extending from a second end of the bit body;

forming each support arm with a first interior surface and a respective spindle extending inwardly from the associated support arm;

forming a cone assembly with an internal cavity having interior surfaces sized to receive a bearing structure associated with the respective spindle;

installing a fluid seal in a generally cylindrical gap formed between interior portions of each cone assembly and exterior portions of the respective spindle; and

forming a diverter groove on the interior surface of each support arm spaced from the respective spindle.

24. The method of claim 23 further comprising forming each diverter groove having variations in dimensions and/or configuration to provide enhanced protection for associated fluid seals and bearing systems by diverting shale, formation cutting and other types of downhole debris away from such fluid seals and bearing systems.

25. The method of claim 23 further comprising forming each diverter groove having a depth which increases relative to a backface of the associated cone assembly.

26. The method of claim 23 further comprising installing at least one diverter plug in the interior surface of the associate support arm proximate the diverter groove to assist in directing fluids containing debris into the associated diverter groove.